|Publication number||US7841234 B2|
|Application number||US 11/882,104|
|Publication date||Nov 30, 2010|
|Priority date||Jul 30, 2007|
|Also published as||CA2693629A1, CA2693629C, CN101765698A, CN101765698B, EP2185793A1, EP2185793A4, US8261607, US20090031796, US20110022336, WO2009017728A1|
|Publication number||11882104, 882104, US 7841234 B2, US 7841234B2, US-B2-7841234, US7841234 B2, US7841234B2|
|Inventors||Don M. Coates, David W. Beck, M. Clark Thompson|
|Original Assignee||Chevron U.S.A. Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (51), Non-Patent Citations (2), Referenced by (1), Classifications (18), Legal Events (2)|
|External Links: USPTO, USPTO Assignment, Espacenet|
Pressure transducers are disclosed, such as transducers that shift the frequency of a reflected signal based on a response to pressure.
2. Background Information
Devices have been used for monitoring downhole conditions of a drilled well, where environmental conditions can be relatively harsh. These downhole conditions include temperature and pressure, among others.
An exemplary sensing device is disclosed. The sensing device includes a shaped elastomer and ferromagnetic material embedded as discrete particles within the shaped elastomer, wherein a percentage by weight of the ferromagnetic particles is selected such that an inductance of the shaped elastomer will vary a predetermined amount for a given compression of the shaped elastomer.
An exemplary system for sensing pressure in a borehole is also disclosed. The system comprises means for generating electromagnetic energy, and means for modulating the electromagnetic energy. The modulating means includes an inductive element comprising a shaped elastomer and ferromagnetic material embedded as discrete particles within the shaped elastomer, wherein a percentage by weight of the ferromagnetic particles is selected such that an inductance of the shaped elastomer will vary a predetermined amount for a given compression of the shaped elastomer.
An exemplary method of sensing pressure uses a transducer that includes a compressible inductive element. The method comprises supplying electromagnetic energy to a transducer which is configured to reflect the electromagnetic energy at a ring frequency determined by an inductance of the transducer, wherein the inductance changes in response to compression of the inductive element. The ring frequency of electromagnetic energy reflected by the transducer is correlated to a pressure value.
Other advantages and features described herein will be more readily apparent to those skilled in the art when reading the following detailed description in connection with the accompanying drawings, wherein:
The inductive sensor 100 can be formed of ferromagnetic material that is potted using an elastomeric potting agent, e.g. silicone rubber or any other suitable elastomeric material as desired. The inductive sensor 100 can include a ferromagnetic blend of various ferromagnetic materials (or particles), such as iron oxides, iron powder, or any other suitable materials as desired. The composition by weight of each magnetic material in the ferromagnetic blend determines various parameters of the inductive sensor 100, which can include but are not limited to an impedance value, core loss, frequency response, temperature response, quality (Q) factor, power handling, and any other controllable parameters or characteristics. Due to the physical properties of the ferromagnetic blend, the inductive sensor 100 can be compressed by an external force, e.g., pressure, such that an inductive value of the sensor 100 will vary in response to the external force. Those of skill in the art will recognize that a ferromagnetic material does not have to comprise iron compounds, but can be comprised of other metal-based ceramics.
In a step 200, ferromagnetic materials can be mixed with a liquid elastomeric material to form a ferromagnetic material-elastomer mixture. The ferromagnetic materials can include a blend of various ferromagnetic-based magnetic materials. The materials can be added in various compositions by weight to establish a desired hardness composition of the rubber matrix, and which determine various parameters and characteristics of the inductive sensor 100, such as an inductance value, for example.
The liquid elastomeric material can include any of a number of known elastomers, such as amorphous polymers or other silicone-based materials as desired.
In a step 202, the ferromagnetic material-elastomer mixture is transferred to a mold, such as a ring, cylinder, or any other suitable shape mold as desired. In step 204, the ferromagnetic material-elastomer mixture in the mold is cured at any suitable temperature (e.g., room temperature or greater), to form an inductive structure. The curing temperature is determined by the material composition of ferromagnetic material-elastomer mixture. The curing temperature can be determined by whether the elastomer is a saturated or unsaturated material. For example, saturated elastomers, such as silicones, fluoroelastomers (e.g., Viton®), and perfluoroelastomers (e.g., Kalrez®) can be cured at room temperature absent a catalyst or curing agent for vulcanization. Unsaturated materials, such as polyisoprene (e.g., butyl rubber) and polybutadiene (e.g., nitrile), for example, can require the introduction of a curing agent such as sulfur to promote vulcanization. Based on the material composition of the elastomeric materials, the inductive sensor 100 can be made compatible with temperatures up to 400° F., or greater.
In a step 206, the inductive structure can be deaerated to remove bubbles. Deaerating enables the expansion of the inductive mold to be controlled and reproducible. One of ordinary skill in the art will recognize that any known deaerating technique or process can be used.
If the inductive sensor 100 is to be used in an environment in which contamination may be present, then the inductive sensor 100 can be configured to include a protective coating and/or mounted in a protective casing. In a step 208, the inductive mold can be encapsulated with a protective material such as Teflon®, for example, and/or encapsulated in a vessel, formed as a cylinder, or any other suitable encapsulating means as desired. One of ordinary skill will appreciate that the disclosed method can be performed by a machine.
The telemetry system 300 includes means, such as a signal generator 302, for generating electromagnetic (EM) energy and applying the EM energy to a transmission means (not shown), such as a borehole casing or production tubing. The signal generator 302 can generate the EM energy as a pulse (e.g., a sequence or series of pulses or chirps), or as a continuous wave. The EM energy can be generated in a range defined between a desired low resolution (e.g., 1 pulse/sec) and a desired high resolution (e.g., 20 kHz or greater) signals. Modulating means, such as one or more downhole transducers 304, are coupled to the production tubing for interacting with and modulating at least some of the EM energy of the pulse at a “ring frequency.” Receiving means, such as a receiver 306 located at or near the surface, receives the EM energy that is reflected by the transducer 304 at the ring frequency. The receiver 306 samples the EM energy at a rate much higher than either of the ring frequency or the frequency of the EM energy so that the original signal can be reproduced.
In embodiments wherein the EM energy is in the form of an EM pulse, an EM pulse generator is used. Non-nuclear means for generating EM pulses are well-known to those in the nuclear-weapons community. Such EM pulse generators are typically used to test electronic devices by simulating EM pulses associated with nuclear blasts. See, e.g., U.S. Pat. No. 3,562,741 (McEvoy et al.); U.S. Pat. No. 4,430,577 (Bouquet); U.S. Pat. No. 4,845,378 (Garbe et al.); and U.S. Pat. No. 5,150,067 (McMillan).
As shown in
When the telemetry system 300 is configured to include multiple transducers 304, each transducer 304 can be configured to operate at a different “ring” frequency. For example, each transducer 304 can include an inductive element 308 having different formulations (i.e. composition by weight, percentage weight) of ferromagnetic material, which result in varying sensitivities to pressure across the multiple transducers 304.
The receiver 306 can include processing means, such as a processor 312. Those of ordinary skill in the art will appreciate that the processor 312 can be implemented as a computer or other suitable hardware and/or software processing means as desired. Prior to placing the transducer 304 into the well, the modulating (ring) frequency of the transducer 304 can be calibrated using a graphical user interface (GUI) associated with the processor 312. As a result, the processor 312 can be configured to store information (e.g., look-up tables, files, and/or databases) that correlate various ring frequency values to observed compression ranges of the inductive element 308.
The inductance of the inductive element 308 can vary based on a degree to which the inductive element is compressed by the observed pressure in the borehole. In a step 402, the receiver 306 receives the reflected EM energy. Based on the prior calibration, the processor 312 of the receiver 306 uses means, such as a look-up table, for correlating the ring frequency of the received EM energy to a pressure value (step 404). For example, the processor 312 determines an inductance value of the inductive element 308 based on the ring frequency of the transducer 304. The processor 312 correlates the inductance value of the inductive element 308 to a degree of compression of the inductive element 308. The processor 312 then associates the compression of the inductive element 308 to the pressure in the well.
While the invention has been described with reference to specific embodiments, this description is merely representative of the invention by way of example only and is not to be construed as limiting the invention, as numerous variations will exist. Various modifications and applications may occur to those skilled in the art without departing from the true spirit and scope of the invention as defined by the appended claims.
|Cited Patent||Filing date||Publication date||Applicant||Title|
|US3320579 *||Apr 11, 1966||May 16, 1967||Frank R Abbott||Compliant variable reluctance electroacoustic transducer|
|US3562741||Apr 5, 1967||Feb 9, 1971||Burroughs Corp||Electromagnetic pulse generating system|
|US4023136||Jun 9, 1975||May 10, 1977||Sperry Rand Corporation||Borehole telemetry system|
|US4160970||Nov 25, 1977||Jul 10, 1979||Sperry Rand Corporation||Electromagnetic wave telemetry system for transmitting downhole parameters to locations thereabove|
|US4218507 *||Sep 8, 1978||Aug 19, 1980||Graham Magnetics, Inc.||Coated particles and process of preparing same|
|US4308499||Jul 2, 1979||Dec 29, 1981||Kali Und Salz A.G.||Method utilizing electromagnetic wave pulses for determining the locations of boundary surfaces of underground mineral deposits|
|US4430577||Feb 2, 1983||Feb 7, 1984||Commissariat A L'energie Atomique||High voltage electromagnetic pulse generator|
|US4839644||Jun 10, 1987||Jun 13, 1989||Schlumberger Technology Corp.||System and method for communicating signals in a cased borehole having tubing|
|US4845378||Feb 29, 1988||Jul 4, 1989||Bbc Brown Boveri Ag||Emp generator|
|US5150067||Apr 16, 1990||Sep 22, 1992||Mcmillan Michael R||Electromagnetic pulse generator using an electron beam produced with an electron multiplier|
|US5355714||Feb 25, 1993||Oct 18, 1994||Nippondenso Co., Ltd.||Pressure sensor using a pressure responsive magnetic film to vary inductance of a coil|
|US5423222 *||Aug 26, 1993||Jun 13, 1995||Westinghouse Electric Corporation||Method for determining the relative amount of deformation induced in a sealing component by a sealing|
|US5451873||Oct 5, 1993||Sep 19, 1995||Schlumberger Technology Corporation||Method and apparatus for determining the in situ larmor frequency of a wellbore NMR tool to compensate for accumulation of magnetic material on the magnet housing of the tool|
|US5467083||Aug 26, 1993||Nov 14, 1995||Electric Power Research Institute||Wireless downhole electromagnetic data transmission system and method|
|US5576703||Dec 19, 1995||Nov 19, 1996||Gas Research Institute||Method and apparatus for communicating signals from within an encased borehole|
|US5587707||Jun 15, 1993||Dec 24, 1996||Flight Refuelling Limited||Data transfer|
|US5680029 *||Apr 26, 1996||Oct 21, 1997||U.S. Philips Corporation||Apparatus for recharging a battery|
|US5686779||Mar 1, 1995||Nov 11, 1997||The United States Of America As Represented By The Secretary Of The Army||High sensitivity temperature sensor and sensor array|
|US5821129||Feb 12, 1997||Oct 13, 1998||Grimes; Craig A.||Magnetochemical sensor and method for remote interrogation|
|US5936913||Jul 24, 1997||Aug 10, 1999||Magnetic Pulse, Inc||Acoustic formation logging system with improved acoustic receiver|
|US5942991||Jun 6, 1995||Aug 24, 1999||Diversified Technologies, Inc.||Resonant sensor system and method|
|US6025725||Dec 4, 1997||Feb 15, 2000||Massachusetts Institute Of Technology||Electrically active resonant structures for wireless monitoring and control|
|US6234257||Apr 16, 1999||May 22, 2001||Schlumberger Technology Corporation||Deployable sensor apparatus and method|
|US6393921||Feb 11, 2000||May 28, 2002||University Of Kentucky Research Foundation||Magnetoelastic sensing apparatus and method for remote pressure query of an environment|
|US6434372||Jan 12, 2001||Aug 13, 2002||The Regents Of The University Of California||Long-range, full-duplex, modulated-reflector cell phone for voice/data transmission|
|US6633236||Jan 24, 2001||Oct 14, 2003||Shell Oil Company||Permanent downhole, wireless, two-way telemetry backbone using redundant repeaters|
|US6670880||Mar 23, 2001||Dec 30, 2003||Novatek Engineering, Inc.||Downhole data transmission system|
|US6766141||Jun 28, 2002||Jul 20, 2004||The Regents Of The University Of California||Remote down-hole well telemetry|
|US6993432||Dec 12, 2003||Jan 31, 2006||Schlumberger Technology Corporation||System and method for wellbore communication|
|US7017662||Nov 18, 2004||Mar 28, 2006||Halliburton Energy Services, Inc.||High temperature environment tool system and method|
|US7114561||Mar 2, 2001||Oct 3, 2006||Shell Oil Company||Wireless communication using well casing|
|US7158049||Mar 24, 2003||Jan 2, 2007||Schlumberger Technology Corporation||Wireless communication circuit|
|US7168487||Dec 18, 2003||Jan 30, 2007||Schlumberger Technology Corporation||Methods, apparatus, and systems for obtaining formation information utilizing sensors attached to a casing in a wellbore|
|US7180826||Oct 1, 2004||Feb 20, 2007||Teledrill Inc.||Measurement while drilling bi-directional pulser operating in a near laminar annular flow channel|
|US7256707||Jun 18, 2004||Aug 14, 2007||Los Alamos National Security, Llc||RF transmission line and drill/pipe string switching technology for down-hole telemetry|
|US7397388||Dec 20, 2004||Jul 8, 2008||Schlumberger Technology Corporation||Borehold telemetry system|
|US7530737||May 18, 2007||May 12, 2009||Chevron U.S.A. Inc.||System and method for measuring temperature using electromagnetic transmissions within a well|
|US7548068||Nov 30, 2004||Jun 16, 2009||Intelliserv International Holding, Ltd.||System for testing properties of a network|
|US20070030762||Mar 24, 2004||Feb 8, 2007||Schlumberger Technology Corporation||Borehole telemetry system|
|US20070107528||Nov 16, 2005||May 17, 2007||Thaddeus Schroeder||Versatile strain sensor employing magnetostrictive electrical conductors|
|US20070206440||May 9, 2007||Sep 6, 2007||Halliburton Energy Services, Inc.||Flexible Piezoelectric for Downhole Sensing, Actuation and Health Monitoring|
|US20070235184||Mar 31, 2006||Oct 11, 2007||Chevron U.S.A. Inc.||Method and apparatus for sensing a borehole characteristic|
|US20080185328||Dec 20, 2005||Aug 7, 2008||Hydropath Holdings Limited||Fluid Treatment Method and Apparatus|
|US20080253230||Apr 13, 2007||Oct 16, 2008||Chevron U.S.A. Inc.||System and method for receiving and decoding electromagnetic transmissions within a well|
|US20080264624||Feb 26, 2008||Oct 30, 2008||Hall David R||Downhole Sensor Assembly|
|US20090226263||May 21, 2009||Sep 10, 2009||Wetch Stephen B||Riser Support System For Use With An Offshore Platform|
|USH1744||Sep 21, 1995||Aug 4, 1998||Clayton; Stanley R.||Wireless remote sensing thermometer|
|EP0314654A1||Oct 21, 1988||May 3, 1989||Saga Petroleum A.S.||Method and apparatus for transmitting data to the surface from an oil well|
|GB2386691A||Title not available|
|GB2425593A||Title not available|
|JPH05267066A *||Title not available|
|1||Goswami et al., "On Subsurface Wireless Data Acquisition System," IEEE Trans. On Geosci. And Rem Sensing, vol. 43(10), pp. 2332-2339 (2005).|
|2||International Search Report mailed Oct. 10, 2008 in International Application No. PCT/US08/09161.|
|Citing Patent||Filing date||Publication date||Applicant||Title|
|WO2015069721A1||Nov 5, 2014||May 14, 2015||Fmc Technologies, Inc.||Continuous sensor measurement in harsh environments|
|Cooperative Classification||G01L9/10, G01L19/086, G01L1/127, G01L9/0004, G01L9/0089, H01F17/062, E21B47/06, H01F2017/048, H01F3/08, H01F21/08, H01F41/0246|
|European Classification||H01F41/02A4, H01F21/08, G01L9/00F, E21B47/06, G01L9/00A4|
|Oct 17, 2007||AS||Assignment|
Owner name: CHEVRON U.S.A INC, CALIFORNIA
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:COATES, DON M.;BECK, DAVID W.;THOMPSON, M. CLARK;REEL/FRAME:019978/0134;SIGNING DATES FROM 20070830 TO 20070918
Owner name: CHEVRON U.S.A INC, CALIFORNIA
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:COATES, DON M.;BECK, DAVID W.;THOMPSON, M. CLARK;SIGNINGDATES FROM 20070830 TO 20070918;REEL/FRAME:019978/0134
|Apr 24, 2014||FPAY||Fee payment|
Year of fee payment: 4